Reliable and accurate data of crude oil viscosity at different temperature and pressure conditions is required in the petroleum industry to calculate the fluids flow in the reservoir, for the design of production facilities and transportation pipelines on the surface. But all above, crude oil viscosity is essential to estimate crude oil recovery in a reservoir, either from natural depletion process (primary production) or from the recovery techniques such as water or gas injection processes (secondary or enhanced production method) (Barrufet, M. A. and Dexheimer, D., Use of an automatic data quality control algorithm for crude oil viscosity data, Fluid Phase Equilibria, 2004, 219, 113-121).
Live crude oil (fluid sample in a single phase extracted from the bottom of the well) largely depends on temperature, pressure, oil density, gas density, gas solubility, molecular structure sizes (asphaltenes and paraffins), and the composition of the hydrocarbon mixture (Barrufet and Dexheimer, 2004). Measuring fluids viscosity in a single-phase at high temperatures and high pressures is one of the most difficult activities in the petroleum industry, particularly due to the complexity of crude oil mixtures, and to the limitations of the appliances used to measure (Dexheimer, D., Jackson, C., Barrufet, M. A., A modification of Pedersen's model for saturated crude oil viscosities using standard black oil PVT data, Fluid Phase Equilibria, 2001, 183-184, 247-257).
There are few apparatuses designed and developed techniques to measure crude oil viscosity at reservoir temperature and pressure conditions. The most common techniques are: (1) a falling ball viscometer and (2) a capillary tube viscometer (Pedersen, K. S., Fredenslund, Aa., Thomassen, P., Properties of oils and natural gases, 1989, Gulf Publishing Company, Houston, Tex., 63-66). The first ones have a limitation in accuracy of viscosity and in the operation range of pressure and temperature conditions, besides they tend to an accumulation and deposition of matter, especially when using crude oils precipitating asphaltenes or paraffins. Besides, these viscometers have the disadvantage of not determine dynamic viscosity (or absolute), but they determine kinematic viscosity and require of the density value of fluid at the same measuring conditions in order to calculate dynamic viscosity. The second ones are difficult to use with different fluids due to cleaning problems, and a more prolonged time is required to reach the state of stabilization when fluids are changed; furthermore, this apparatus is extremely sensitive, especially at high pressures and it requires an accurate calibration of the differential pressure transducer, which is frequently a source of error (U.S. Pat. No. 4,660,413).
U.S. Pat. No. 4,890,482 refers to a method and apparatus to measure fluid viscosity. The apparatus described under this patent is related to a transitory flow capillary viscometer that measures viscosity of a highly viscous fluid. The operation principle consists on filling the capillary tube with the test fluid inducing a change in the pressure through the inlet and outlet of the capillary tube causing the fluid to flow. The resulting decrease in the pressure drop is a function of time, which is monitored to provide an indicative measure of fluid viscosity flowing through the capillary tube.
U.S. Pat. No. 4,660,413 refers to an apparatus and a method to determine the viscosity and density of a fluid by means of ascendant circulation of the fluid through a tube, which has a cup in the inner part, with a constant flow rate suspending the cup at equilibrium position. Then, a mass is added to the cup and a new flow rate of the fluid suspending the cup at equilibrium position is determined. Density and viscosity of the fluid are determined as a function of the two values of the fluid flow rate, and the apparatus characteristics.
U.S. Pat. No. 2,348,732 relates to a method and apparatus to determine fluids viscosity, as well as the oil density at dynamic conditions, such as the fluid was displaced through the pipeline.
U.S. Pat. No. 2,209,755 refers to an apparatus to measure fluids viscosity, such as lubricating oil, fuel oil, molasses, bitumen and substances with similar characteristics. This apparatus can also be applied to obtain an indication of the suspensions and emulsions consistency.
A viscometer of a capillary tube is described in literature to measure heavy oil viscosity and light hydrocarbon mixtures, at temperatures from ambient temperature to 450 K, and at pressures ranging from 0.1 MPa to 34 MPa (Barrufet, M. A., and Setiadarma, A., Experimental viscosities of heavy oil mixtures up to 450 K and high pressures using a mercury capillary viscometer, Journal of Petroleum Science & Engineering, 2003, 40, 17-26); the operation principle of the apparatus used in measurements consists on measuring the differential pressure of the laminar flow of a single-phase fluid along the capillary coils, and to convert it to viscosity by means of the Hagen-Poiseuille equation.
Another apparatus commonly used is the rotating viscometer measuring absolute viscosity by measuring the torque of a sample, and converting it to an absolute-viscosity value. However, the main limitation of this device is the pressure that can be reached in the system (Barrufet and Setiadarma, 2003). Rotational and vibrational viscometers, which can be an alternative to measure crude oil viscosity, are difficult to use at high temperatures and pressures (U.S. Pat. No. 4,890,482).
Despite counting on these apparatuses, most measurements carried out through these viscometers are not direct, that is, they do not measure dynamic viscosity directly, but they measure kinematic viscosity and require the density value, at the same temperature and pressure conditions, to calculate absolute viscosity (Barrufet and Setiadarma, 2003). In addition, a large amount of volume of the sample is required for the measuring test. Therefore an adequate process and an apparatus are required to determine highly viscous fluids viscosity at different temperature and pressure conditions.
The present invention is new due to consist on a process to measure dynamic viscosity of bottom-hole monophasic samples at a constant temperature and different pressures, as well as determine their thermodynamic behavior (p,μ)T from the reservoir pressure (μo viscosity by above the bubble point pressure, pb) to the atmospheric pressure (μod dead crude oil viscosity), including dynamic viscosities at the bubble point pressure (μob) and by below of this pressure (μb); also is possible to determine the phases behavior L-V (saturation curve) of such fluids of reservoir. Unlike to the different methods described before, this method describes the dynamic viscosity directly of reservoir fluids at high temperature (up to 463 K) and high pressure (68.9 MPa) conditions at a wide range of viscosity (up to 10000 cP) and a 20-50 mL sample volume is required; essentially, the invention consists on a process to measure dynamic viscosity of heavy live crude oil by means of an apparatus containing a sensor based on a simple and novel technology: at a constant electromagnetic force. This apparatus uses a piston, calibrated in a determined range of viscosities, which is immersed in the crude oil to be analyzed. The piston displacement is resisted by viscous drag of the fluid, a characteristic used to obtain an accurate measurement of absolute viscosity. Time required by the piston to travel at a fixed distance is related to fluid dynamic viscosity confined in a measuring chamber. Therefore as the fluid in the measuring chamber is to be more viscous, the piston displacement will be slower.